Methods and systems for evaluating a boundary between a consolidating spacer fluid and a cement composition

ABSTRACT

Disclosed are spacer fluids and methods of use in subterranean formations. Embodiments may include use of consolidating spacer fluids in displacement of drilling fluids from a well bore annulus. Embodiments may include determining the boundary between a cement composition and a consolidating spacer fluid based on presence of tagging material in the well bore.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. application Ser. No.13/725,833, entitled “Consolidating Spacer Fluids and Methods of Use,”filed on Dec. 21, 2012, which is a continuation-in-part of U.S.application Ser. No. 13/535,145, entitled “Foamed Spacer FluidsContaining Cement Kiln Dust and Methods of Use,” filed on Jun. 27, 2012,which is a continuation-in-part of U.S. application Ser. No. 12/895,436,entitled “Spacer Fluids Containing Cement Kiln Dust and Methods of Use,”filed on Sep. 30, 2010, which is a continuation-in-part of U.S.application Ser. No. 12/264,010, now U.S. Pat. No. 8,333,240, entitled“Reduced Carbon Footprint Sealing Compositions for Use in SubterraneanFormations,” filed on Nov. 3, 2008, which is a continuation-in-part ofU.S. application Ser. No. 11/223,669, now U.S. Pat. No. 7,445,669,entitled “Settable Compositions Comprising Cement Kiln Dust andAdditive(s),” filed Sep. 9, 2005, the entire disclosures of which areincorporated herein by reference.

BACKGROUND

The present invention relates to spacer fluids for use in subterraneanoperations and, more particularly, in certain embodiments, toconsolidating spacer fluids and methods of use in subterraneanformations.

Spacer fluids are often used in subterranean operations to facilitateimproved displacement efficiency when introducing new fluids into a wellbore. For example, a spacer fluid can be used to displace a fluid in awell bore before introduction of another fluid. When used for drillingfluid displacement, spacer fluids can enhance solids removal as well asseparate the drilling fluid from a physically incompatible fluid. Forinstance, in primary cementing operations, the spacer fluid may beplaced into the well bore to separate the cement composition from thedrilling fluid. Spacer fluids may also be placed between differentdrilling fluids during drilling change outs or between a drilling fluidand completion brine. Spacer fluids typically do not consolidate in thatthe spacer fluids typically do not develop significant gel orcompressive strength.

To be effective, the spacer fluid can have certain characteristics. Forexample, the spacer fluid may be compatible with the displaced fluid andthe cement composition. This compatibility may also be present atdownhole temperatures and pressures. In some instances, it is alsodesirable for the spacer fluid to leave surfaces in the well bore waterwet, thus facilitating bonding with the cement composition. Rheology ofthe spacer fluid can also be important. A number of differentrheological properties may be important in the design of a spacer fluid,including yield point, plastic viscosity, gel strength, and shearstress, among others. While rheology can be important in spacer fluiddesign, conventional spacer fluids may not have the desired rheology atdownhole temperatures. For instance, conventional spacer fluids mayexperience undesired thermal thinning at elevated temperatures. As aresult, conventional spacer fluids may not provide the desireddisplacement in some instances.

SUMMARY

The present invention relates to spacer fluids for use in subterraneanoperations and, more particularly, in certain embodiments, toconsolidating spacer fluids and methods of use in subterraneanformulations.

An embodiment may comprise displacing a drilling fluid disposed in awell bore annulus, comprising: designing a spacer fluid to meet at leastone property under predetermined well bore conditions, wherein theproperty is selected from the group consisting of: (i) a yield point offrom about 25 Pascals to about 250 Pascals, (ii) a static gel strengthof from about 70 lbf/100 ft² to about 500 lbf/100 ft², (iii) a yieldlimit in compression from about 1 psi to about 2,000 psi, and (iv) anunconfined uniaxial compressive strength of from about 5 psi to about10,000 psi; using the spacer fluid to displace at least a portion of thedrilling fluid from the well bore annulus; and allowing at least aportion of the spacer fluid to consolidate in the well bore, and whereinthe portion of the spacer fluid consolidates in the well bore to meetthe property.

Another embodiment may comprise a method of displacing a drilling fluiddisposed in a well bore annulus, comprising: using a consolidatingspacer fluid to displace at least a portion of the drilling fluid fromthe well bore annulus; and allowing at least a portion of theconsolidating spacer fluid to consolidate in the well bore annulus,wherein the portion of the consolidating spacer fluid has a zero geltime of about 4 hours or less.

Another embodiment may comprise a method of displacing a drilling fluiddisposed in a well bore annulus, comprising: using a consolidatingspacer fluid to displace at least a portion of the drilling fluid fromthe well bore annulus; and allowing at least a portion of theconsolidating spacer fluid to consolidate in the well bore annulus,wherein the portion of the consolidating spacer fluid has a transitiontime of about 45 minutes or less.

Another embodiment may comprise a method of displacing a drilling fluiddisposed in a well bore annulus, comprising: introducing a consolidatingspacer fluid into the well bore annulus to displace at least a portionof the drilling fluid from the well bore annulus; and allowing at leasta portion of the consolidating spacer fluid to consolidate in the wellbore annulus; wherein the consolidating spacer fluid comprises water andat least one additive selected from the group consisting of kiln dust,gypsum, fly ash, bentonite, hydroxyethyl cellulose, sodium silicate, ahollow microsphere, gilsonite, perlite, a gas, an organic polymer, abiopolymer, latex, ground rubber, a surfactant, crystalline silica,amorphous silica, silica flour, fumed silica, nano-clay, salt, fiber,hydratable clay, rice husk ash, micro-fine cement, metakaolin, zeolite,shale, pumicite, Portland cement, Portland cement interground withpumice, barite, slag, lime, and any combination thereof; and wherein theportion of the consolidating spacer fluid has a zero gel time of about 8hours or less.

Another embodiment may comprise a method of displacing a drilling fluiddisposed in a well bore annulus, comprising: introducing a consolidatingspacer fluid into the well bore annulus to displace at least a portionof the drilling fluid from the well bore annulus; allowing at least aportion of the consolidating spacer fluid to consolidate in the wellbore annulus; and measuring consolidation properties of the portion ofthe consolidating spacer fluid in the well bore annulus.

Another embodiment of a method of may comprise a method of evaluating aspacer fluid for use in separating a drilling fluid and a cementcomposition in a well bore comprising: providing the spacer fluid; andmeasuring a transition time of the spacer fluid.

Another embodiment may comprise a method of evaluating a spacer fluidfor use in separating a drilling fluid and a cement composition in awell bore comprising: providing the spacer fluid; and measuring a zerogel time of the spacer fluid.

Another embodiment may comprise a consolidating spacer fluid thatseparates a drilling fluid and a cement composition in a well bore,comprising: water; and at least one additive selected from the groupconsisting of kiln dust, gypsum, fly ash, bentonite, hydroxyethylcellulose, sodium silicate, a hollow microsphere, gilsonite, perlite, agas, an organic polymer, a biopolymer, latex, ground rubber, asurfactant, crystalline silica, amorphous silica, silica flour, fumedsilica, nano-clay, salt, fiber, hydratable clay, rice husk ash,micro-fine cement, metakaolin, zeolite, shale, pumicite, Portlandcement, Portland cement interground with pumice, barite, slag, lime, andany combination thereof; and wherein the portion of the consolidatingspacer fluid has a zero gel time of about 4 hours or less.

Another embodiment may comprise a method of evaluating a boundarybetween a consolidating spacer fluid and a cement composition,comprising: introducing a consolidating spacer fluid into a well bore todisplace at least a portion of a drilling fluid from the well bore;introducing a cement composition into the well bore behind theconsolidating spacer fluid; allowing at least a portion of theconsolidating spacer fluid to consolidate in the well bore; anddetermining the boundary between the cement composition and theconsolidating spacer fluid based on presence of a tagging material inthe well bore.

Another method may comprise a method of evaluating a boundary between aconsolidating spacer fluid and a cement composition comprising:introducing a consolidating spacer fluid into a well bore to displace atleast a portion of a drilling fluid from the well bore, wherein theconsolidating spacer fluid comprises water and cement kiln dust;introducing a cement composition into the well bore behind theconsolidating spacer fluid, wherein a first portion of the cementcomposition comprises a thermal neutron absorbing material; allowing atleast a portion of the consolidating spacer fluid to consolidate in thewell bore; and determining the top of the cement composition in the wellbore based on presence of the thermal neutron absorbing material in thefirst portion.

Yet another method may comprise a system for evaluating a spacer fluidboundary in a well bore, comprising: a consolidating spacer fluid; acement composition; mixing equipment for separately mixing theconsolidating spacer fluid and the cement composition; and pumpingequipment for separately delivering the consolidating spacer fluid andthe cement composition to a well bore, wherein at least one of theconsolidating spacer fluid or the cement composition comprises a taggingmaterial.

The features and advantages of the present invention will be readilyapparent to those skilled in the art. While numerous changes may be madeby those skilled in the art, such changes are within the spirit of theinvention.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention, and should not be used to limit or define theinvention.

FIG. 1 is an illustration of an embodiment of a well bore cementingsystem, depicting the cement being mixed and then pumped to the wellbore.

FIG. 2 is an illustration of an embodiment of a well bore cementingsystem, depicting the cement being pumped into the casing and thenupward into the annulus.

FIG. 3 is an illustration of an embodiment of a cement system with aconsolidating spacer fluid used in conjunction with a tagging materialin the leading portion of the cement composition.

FIG. 4 is a graph showing measured static gel strength values at varioustemperature and pressure readings as a factor of time for an exampleconsolidating spacer fluid.

FIG. 5 is a graph showing measured static gel strength values at varioustemperature and pressure readings as a factor of time for an exampleconsolidating spacer fluid.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to spacer fluids for use in subterraneanoperations and, more particularly, in certain embodiments, to spacerfluids that comprise cement kiln dust (“CKD”) and methods that use CKDfor enhancing one or more rheological properties of a spacer fluid. Inaccordance with present embodiments, the spacer fluids may improve theefficiency of well bore cleaning and well bore fluid removal.Embodiments of the spacer fluids may be foamed. Embodiments of thespacer fluids may be consolidating. For example, the spacer fluids maydevelop gel strength and/or compressive strength when left in a wellbore.

There may be several potential advantages to the methods andcompositions of the present invention, only some of which may be alludedto herein. One of the many potential advantages of the methods andcompositions of the present invention is that the CKD may be used inspacer fluids as a rheology modifier allowing foimulation of a spacerfluid with desirable rheological properties. Another potential advantageof the methods and compositions of the present invention is thatinclusion of the CKD in the spacer fluids may result in a spacer fluidwithout undesired thermal thinning. Yet another potential advantage ofthe present invention is that spacer fluids comprising CKD may be moreeconomical than conventional spacer fluids, which are commonly preparedwith higher cost additives. Yet another potential advantage of thepresent invention is that foamed spacer fluids comprising CKD may beused for displacement of lightweight drilling fluids. Yet anotherpotential advantage is that the consolidating spacer fluids may possessadditional physical characteristics that can provide additional benefitsto the well bore operations. For example, the consolidating spacerfluids may develop gel and/or compressive strength in a well boreannulus. Accordingly, the consolidating spacer fluid left in the wellbore may function to provide a substantially impermeable barrier to sealoff formation fluids and gases and consequently serve to mitigatepotential fluid migration. The consolidating spacer fluid may also actto consolidate mud filtercake remaining on the walls of the well boreand/or pipe string, as well as protecting the pipe string or otherconduit from corrosion. Consolidating spacer fluids may also serve toprotect the erosion of the cement sheath formed by subsequentlyintroduced cement compositions.

Embodiments of the spacer fluids of the present invention may comprisewater and CKD. In some embodiments, the spacer fluids may consolidatewhen left in a well bore. For example, the spacer fluid may set andharden by reaction of the CKD in the water. In some embodiments, thespacer fluids may be foamed. For example, the foamed spacer fluids maycomprise water, CKD, a foaming agent, and a gas. A foamed spacer fluidmay be used, for example, where it is desired for the spacer fluid to belightweight. In accordance with present embodiments, the spacer fluidmay be used to displace a first fluid from a well bore with the spacerfluid having a higher yield point than the first fluid. For example, thespacer fluid may be used to displace at least a portion of a drillingfluid from the well bore. Other optional additives may also be includedin embodiments of the spacer fluids as desired for a particularapplication. For example, the spacer fluids may further compriseviscosifying agents, organic polymers, dispersants, surfactants,weighting agents, and any combination thereof.

The spacer fluids generally should have a density suitable for aparticular application as desired by those of ordinary skill in the art,with the benefit of this disclosure. In some embodiments, the spacerfluids may have a density in the range of from about 4 pounds per gallon(“ppg”) to about 24 ppg. In other embodiments, the spacer fluids mayhave a density in the range of about 4 ppg to about 17 ppg. In yet otherembodiments, the spacer fluids may have a density in the range of about8 ppg to about 13 ppg. Embodiments of the spacer fluids may be foamed orunfoamed or comprise other means to reduce their densities known in theart, such as lightweight additives. Those of ordinary skill in the art,with the benefit of this disclosure, will recognize the appropriatedensity for a particular application.

The water used in an embodiment of the spacer fluids may include, forexample, freshwater, saltwater (e.g., water containing one or more saltsdissolved therein), brine (e.g., saturated saltwater produced fromsubterranean formations), seawater, or any combination thereof.Generally, the water may be from any source, provided that the waterdoes not contain an excess of compounds that may undesirably affectother components in the spacer fluid. The water is included in an amountsufficient to form a pumpable spacer fluid. In some embodiments, thewater may be included in the spacer fluids in an amount in the range offrom about 15% to about 95% by weight of the spacer fluid. In otherembodiments, the water may be included in the spacer fluids of thepresent invention in an amount in the range of from about 25% to about85% by weight of the spacer fluid. One of ordinary skill in the art,with the benefit of this disclosure, will recognize the appropriateamount of water to include for a chosen application.

The CKD may be included in embodiments of the spacer fluids as arheology modifier. Among other things, using CKD in embodiments of thepresent invention can provide spacer fluids having rheology suitable fora particular application. Desirable rheology may be advantageous toprovide a spacer fluid that is effective for drilling fluiddisplacement, for example. In some instances, the CKD can be used toprovide a spacer fluid with a low degree of theimal thinning. Forexample, the spacer fluid may even have a yield point that increases atelevated temperatures, such as those encountered downhole.

CKD is a material generated during the manufacture of cement that iscommonly referred to as cement kiln dust. The term “CKD” is used hereinto mean cement kiln dust as described herein and equivalent forms ofcement kiln dust made in other ways. The term “CKD” typically refers toa partially calcined kiln feed which can be removed from the gas streamand collected, for example, in a dust collector during the manufactureof cement. Usually, large quantities of CKD are collected in theproduction of cement that are commonly disposed of as waste. Disposal ofthe waste CKD can add undesirable costs to the manufacture of thecement, as well as the environmental concerns associated with itsdisposal. Because the CKD is commonly disposed as a waste material,spacer fluids prepared with CKD may be more economical than conventionalspacer fluids, which are commonly prepared with higher cost additives.The chemical analysis of CKD from various cement manufactures variesdepending on a number of factors, including the particular kiln feed,the efficiencies of the cement production operation, and the associateddust collection systems. CKD generally may comprise a variety of oxides,such as SiO₂, Al₂O₃, Fe₂O₃, CaO, MgO, SO₃, Na₂O, and K₂O.

The CKD may be included in the spacer fluids in an amount sufficient toprovide, for example, the desired rheological properties. In someembodiments, the CKD may be present in the spacer fluids in an amount inthe range of from about 1% to about 65% by weight of the spacer fluid(e.g., about 1%, about 5%, about 10%, about 15%, about 20%, about 25%,about 30%, about 35%, about 40%, about 45%, about 50%, about 55%, about60%, about 65%, etc.). In some embodiments, the CKD may be present inthe spacer fluids in an amount in the range of from about 5% to about60% by weight of the spacer fluid. In some embodiments, the CKD may bepresent in an amount in the range of from about 20% to about 35% byweight of the spacer fluid. Alternatively, the amount of CKD may beexpressed by weight of dry solids. As used herein, the term “by weightdry solids” refers to the amount of a component, such as CKD, relativeto the overall amount of dry solids used in preparation of the spacerfluid. For example, the CKD may be present in an amount in a range offrom about 1% to 100% by weight of dry solids (e.g., about 1%, about 5%,about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about70%, about 80%, about 90%, 100%, etc.). In some embodiments, the CKD maybe present in an amount in the range of from about 50% to 100% and,alternatively, from about 80% to 100% by weight of dry solids. One ofordinary skill in the art, with the benefit of this disclosure, willrecognize the appropriate amount of CKD to include for a chosenapplication.

While the preceding description describes CKD, the present invention isbroad enough to encompass the use of other partially calcined kilnfeeds. For example, embodiments of the spacer fluids may comprise limekiln dust, which is a material that is generated during the manufactureof lime. The tem lime kiln dust typically refers to a partially calcinedkiln feed which can be removed from the gas stream and collected, forexample, in a dust collector during the manufacture of lime. Thechemical analysis of lime kiln dust from various lime manufacturersvaries depending on a number of factors, including the particularlimestone or dolomitic limestone feed, the type of kiln, the mode ofoperation of the kiln, the efficiencies of the lime productionoperation, and the associated dust collection systems. Lime kiln dustgenerally may comprise varying amounts of free lime, lime stone, and/ordolomitic limestone and a variety of oxides, such as SiO₂, Al₂O₃, Fe₂O₃,CaO, MgO, SO₃, Na₂O, and K₂O, and other components, such as chlorides.

Optionally, embodiments of the spacer fluids may further comprise flyash. A variety of fly ashes may be suitable, including fly ashclassified as Class C or Class F fly ash according to American PetroleumInstitute, API Specification for Materials and Testing for Well Cements,API Specification 10, Fifth Ed., Jul. 1, 1990. Suitable examples of flyash include, but are not limited to, POZMIX® A cement additive,commercially available from Halliburton Energy Services, Inc., Duncan,Okla. Where used, the fly ash generally may be included in the spacerfluids in an amount desired for a particular application. In someembodiments, the fly ash may be present in the spacer fluids in anamount in the range of from about 1% to about 60% by weight of thespacer fluid (e.g., about 5%, about 10%, about 15%, about 20%, about25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%,etc.). In some embodiments, the fly ash may be present in the spacerfluids in an amount in the range of from about 1% to about 35% by weightof the spacer fluid. In some embodiments, the fly ash may be present inthe spacer fluids in an amount in the range of from about 1% to about10% by weight of the spacer fluid. Alternatively, the amount of fly ashmay be expressed by weight of dry solids. For example, the fly ash maybe present in an amount in a range of from about 1% to about 99% byweight of dry solids (e.g., about 1%, about 5%, about 10%, about 20%,about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about90%, about 99%, etc.). In some embodiments, the fly ash may be presentin an amount in the range of from about 1% to about 20% and,alternatively, from about 1% to about 10% by weight of dry solids. Oneof ordinary skill in the art, with the benefit of this disclosure, willrecognize the appropriate amount of the fly ash to include for a chosenapplication.

Optionally, embodiments of the spacer fluids may further comprisebarite. In some embodiments, the barite may be sized barite. Sizedbarite generally refers to barite that has been separated, sieved,ground, or otherwise sized to produce barite having a desired particlesize. For example, the barite may be sized to produce barite having aparticle size less than about 200 microns in size. Where used, thebarite generally may be included in the spacer fluids in an amountdesired for a particular application. In some embodiments, the baritemay be present in the spacer fluids in an amount in the range of fromabout 1% to about 60% by weight of the consolidating spacer fluid (e.g.,about 5%, about 10%, about 15%, about 20%, about 25%, about 30%, about35%, about 40%, about 45%, about 50%, about 55%, etc.). In someembodiments, the barite may be present in the spacer fluids in an amountin the range of from about 1% to about 35% by weight of the spacerfluid. In some embodiments, the barite may be present in the spacerfluids in an amount in the range of from about 1% to about 10% by weightof the spacer fluid. Alternatively, the amount of barite may beexpressed by weight of dry solids. For example, the barite may bepresent in an amount in a range of from about 1% to about 99% by weightof dry solids (e.g., about 1%, about 5%, about 10%, about 20%, about30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%,about 99%, etc.). In some embodiments, the barite may be present in anamount in the range of from about 1% to about 20% and, alternatively,from about 1% to about 10% by weight of dry solids. One of ordinaryskill in the art, with the benefit of this disclosure, will recognizethe appropriate amount of the barite to include for a chosenapplication.

Optionally, embodiments of the spacer fluids may further comprisepumicite. Where used, the pumicite generally may be included in thespacer fluids in an amount desired for a particular application. In someembodiments, the pumicite may be present in the spacer fluids in anamount in the range of from about 1% to about 60% by weight of thespacer fluid (e.g., about 5%, about 10%, about 15%, about 20%, about25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%,etc.). In some embodiments, the pumicite may be present in the spacerfluids in an amount in the range of from about 1% to about 35% by weightof the spacer fluid. In some embodiments, the pumicite may be present inthe spacer fluids in an amount in the range of from about 1% to about10% by weight of the spacer fluid. Alternatively, the amount of pumicitemay be expressed by weight of dry solids. For example, the pumicite maybe present in an amount in a range of from about 1% to about 99% byweight of dry solids (e.g., about 1%, about 5%, about 10%, about 20%,about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about90%, about 99%, etc.). In some embodiments, the pumicite may be presentin an amount in the range of from about 1% to about 20% and,alternatively, from about 1% to about 10% by weight of dry solids. Oneof ordinary skill in the art, with the benefit of this disclosure, willrecognize the appropriate amount of the pumicite to include for a chosenapplication.

Optionally, embodiments of the spacer fluids may further comprise a freewater control additive. As used herein, the term “free water controladditive” refers to an additive included in a liquid for, among otherthings, reducing (or preventing) the presence of free water in theliquid. Free water control additive may also reduce (or prevent) thesettling of solids. Examples of suitable free water control additivesinclude, but are not limited to, bentonite, amorphous silica,hydroxyethyl cellulose, and combinations thereof. An example of asuitable free water control additive is SA1015™ suspending agent,available from Halliburton Energy Services, Inc. Another example of asuitable free water control additive is WG-17™ solid additive, availablefrom Halliburton Energy Services, Inc. The free water control additivemay be provided as a dry solid in some embodiments. Where used, the freewater control additive may be present in an amount in the range of fromabout 0.1% to about 16% by weight of dry solids, for example. Inalternative embodiments, the free water control additive may be presentin an amount in the range of from about 0.1% to about 2% by weight ofdry solids.

In some embodiments, the spacer fluids may further comprise alightweight additive. The lightweight additive may be included to reducethe density of embodiments of the spacer fluids. For example, thelightweight additive may be used to form a lightweight spacer fluid, forexample, having a density of less than about 13 ppg. The lightweightadditive typically may have a specific gravity of less than about 2.0.Examples of suitable lightweight additives may include sodium silicate,hollow microspheres, gilsonite, perlite, and combinations thereof. Anexample of a suitable sodium silicate is ECONOLITE™ additive, availablefrom Halliburton Energy Services, Inc. Where used, the lightweightadditive may be present in an amount in the range of from about 0.1% toabout 20% by weight of dry solids, for example. In alternativeembodiments, the lightweight additive may be present in an amount in therange of from about 1% to about 10% by weight of dry solids.

As previously mentioned, embodiments of the spacer fluids may be foamedwith a foaming agent and a gas, for example, to provide a spacer fluidwith a reduced density. It should be understood that reduced densitiesmay be needed for embodiments of the spacer fluids to more approximatelymatch the density of a particular drilling fluid, for example, wherelightweight drilling fluids are being used. A drilling fluid may beconsidered lightweight if it has a density of less than about 13 ppg,alternatively, less than about 10 ppg, and alternatively less than about9 ppg. In some embodiments, the spacer fluids may be foamed to have adensity within about 10% of the density of the drilling fluid and,alternatively, within about 5% of the density of the drilling fluid.While techniques, such as lightweight additives, may be used to reducethe density of the spacer fluids comprising CKD without foaming, thesetechniques may have drawbacks. For example, reduction of the spacerfluid's density to below about 13 ppg using lightweight additives mayproduce unstable slurries, which can have problems with settling ofsolids, floating of lightweight additives, and free water, among others.Accordingly, the spacer fluid may be foamed to provide a spacer fluidhaving a reduced density that is more stable.

Therefore, in some embodiments, the spacer fluids may be foamed andcomprise water, CKD, a foaming agent, and a gas. Optionally, to providea spacer fluid with a lower density and more stable foam, the foamedspacer fluid may further comprise a lightweight additive, for example.With the lightweight additive, a base slurry may be prepared that maythen be foamed to provide an even lower density. In some embodiments,the foamed spacer fluid may have a density in the range of from about 4ppg to about 13 ppg and, alternatively, about 7 ppg to about 9 ppg. Inone particular embodiment, a base slurry may be foamed from a density ofin the range of from about 9 ppg to about 13 ppg to a lower density, forexample, in a range of from about 7 ppg to about 9 ppg.

The gas used in embodiments of the foamed spacer fluids may be anysuitable gas for foaming the spacer fluid; including, but not limited toair, nitrogen, and combinations thereof. Generally, the gas should bepresent in embodiments of the foamed spacer fluids in an amountsufficient to form the desired foam. In certain embodiments, the gas maybe present in an amount in the range of from about 5% to about 80% byvolume of the foamed spacer fluid at atmospheric pressure,alternatively, about 5% to about 55% by volume, and, alternatively,about 15% to about 30% by volume.

Where foamed, embodiments of the spacer fluids may comprise a foamingagent for providing a suitable foam. As used herein, the term “foamingagent” refers to a material or combination of materials that facilitatethe formation of a foam in a liquid. Any suitable foaming agent forforming a foam in an aqueous liquid may be used in embodiments of thespacer fluids. Examples of suitable foaming agents may include, but arenot limited to: mixtures of an ammonium salt of an alkyl ether sulfate,a cocoamidopropyl betaine surfactant, a cocoamidopropyl dimethylamineoxide surfactant, sodium chloride, and water; mixtures of an ammoniumsalt of an alkyl ether sulfate surfactant, a cocoamidopropylhydroxysultaine surfactant, a cocoamidopropyl dimethylamine oxidesurfactant, sodium chloride, and water; hydrolyzed keratin; mixtures ofan ethoxylated alcohol ether sulfate surfactant, an alkyl or alkeneamidopropyl betaine surfactant, and an alkyl or alkene dimethylamineoxide surfactant; aqueous solutions of an alpha-olefinic sulfonatesurfactant and a betaine surfactant; and combinations thereof. Anexample of a suitable foaming agent is FOAMER™ 760 foamer/stabilizer,available from Halliburton Energy Services, Inc. Suitable foaming agentsare described in U.S. Pat. Nos. 6,797,054, 6,547,871, 6,367,550,6,063,738, and 5,897,699, the entire disclosures of which areincorporated herein by reference.

Generally, the foaming agent may be present in embodiments of the foamedspacer fluids in an amount sufficient to provide a suitable foam. Insome embodiments, the foaming agent may be present in an amount in therange of from about 0.8% to about 5% by volume of the water (“bvow”).

A wide variety of additional additives may be included in the spacerfluids as deemed appropriate by one skilled in the art, with the benefitof this disclosure. Examples of such additives include, but are notlimited to: supplementary cementitious materials, weighting agents,viscosifying agents (e.g., clays, hydratable polymers, guar gum), fluidloss control additives, lost circulation materials, filtration controladditives, dispersants, defoamers, corrosion inhibitors, scaleinhibitors, formation conditioning agents, and a water-wettingsurfactants. Water-wetting surfactants may be used to aid in removal ofoil from surfaces in the well bore (e.g., the casing) to enhance cementand consolidating spacer fluid bonding. Examples of suitable weightingagents include, for example, materials having a specific gravity of 3 orgreater, such as barite. Specific examples of these, and other,additives include: organic polymers, biopolymers, latex, ground rubber,surfactants, crystalline silica, amorphous silica, silica flour, fumedsilica, nano-clays (e.g., clays having at least one dimension less than100 nm), salts, fibers, hydratable clays, microspheres, rice husk ash,micro-fine cement (e.g., cement having an average particle size of fromabout 5 microns to about 10 microns), metakaolin, zeolite, shale,Portland cement, Portland cement interground with pumice, perlite,barite, slag, lime (e.g., hydrated lime), gypsum, and any combinationsthereof, and the like. In some embodiments, a supplementary cementitiousmaterial may be included in the spacer fluid in addition to or in placeof all or a portion of the CKD. Examples of suitable supplementarycementitious materials include, without limitation, Portland cement,Portland cement interground with pumice, micro-fine cement, fly ash,slag, pumicite, gypsum and any combination thereof. A person havingordinary skill in the art, with the benefit of this disclosure, willreadily be able to determine the type and amount of additive useful fora particular application and desired result.

As previously mentioned, embodiments of the spacer fluids may beconsolidating in that the spacer fluids may develop gel strength and/orcompressive strength in the well bore. Consolidation is defined hereinas one of three types of material behavior: Type 1 consolidation isidentifiable as a gelled fluid that can be moved and/or pumped when thehydraulic shear stress exceeds the yield point (YP) of the gel. Type 2consolidation is identifiable as a plastic semi-solid that canexperience “plastic deformation” if the shear stress, compressivestress, or tensile stress exceeds the “plastic yield limit.” Type 3consolidation is identifiable as a rigid solid similar to regular setcement. During a steady progressive strain rate during conventionalcompressive testing, both confined and unconfined, a Type 3 consolidatedmaterial would exhibit linear elastic Hookean stress-strain behavior,followed by some plastic yield and/or mechanical failure. This novelconsolidating spacer fluid may transform from the pumpable fluid thatwas placed during the normal displacement operation to Type 1 and/orfurther progress to Type 2 and/or further progress to Type 3. It shouldbe understood that the consolidation of the spacer fluid is at well boreconditions and, as will be appreciated by those of ordinary skill in theart, well bore conditions may vary. However, embodiments of the spacerfluids may be characterized by exhibiting Type 1, Type 2, or Type 3consolidation under specific well bore conditions.

Specific examples of how to characterize a Type I consolidation includemeasuring the yield stress. Type 1 consolidation exhibits a YP fromabout 25 Pascals to about 250 Pascals, where YP is measured by one ofthe methods described in U.S. Pat. No. 6,874,353, namely: using a seriesof parallel vertical blades on a rotor shaft, referred to by thoseskilled in the art as the “Vane Method”; or using the new device andmethod also described in U.S. Pat. No. 6,874,353. Another method used todefine the YP of Type 1 consolidation is defined in Morgan, R. G.,Suter, D. A., and Sweat, V. A., Mathematical Analysis of a Simple BackExtrusion Rheometer, ASAE Paper No. 79-6001. Additionally, other methodscommonly known to those skilled in the art may be used to define the YPof Type 1 consolidated spacer fluids. Alternatively, another method ofcharacterizing a Type 1 consolidation includes measuring the gelledstrength of the material, which may be defined as “Static Gel Strength”(SGS) as is defined and measured in accordance with the API RecommendedPractice on Determining the Static Gel Strength of Cement Formations,ANSI/API Recommended Practice 10B-6. A Type 1 consolidation may exhibitSGS values from about 70 lbf/100 ft² up to about 500 lbf/100 ft².

Specific examples of how to characterize a Type 2 consolidation includemeasuring the yield limit in compression (YL-C). The YL-C is simply theuniaxial compressive stress at which the material experiences apermanent defoiivation. Permanent deformation refers to a measurabledeformation strain that does not return to zero over a period of timethat is on the same order of magnitude as the total time required toconduct the measurement. YL-C may range from 1 psi (lbf/sq.in.) to 2,000psi, with the most common values ranging from 5 psi to 500 psi.

Specific examples of how to characterize a Type 3 consolidation includemeasuring the compressive strength. Type 3 consolidation will exhibitunconfined uniaxial compressive strengths ranging from about 5 psi toabout 10,000 psi, while the most common values will range from about 10psi to about 2,500 psi. These values are achieved in 7 days or less.Some formulations may be designed so as to provide significantcompressive strengths with 24 hours to 48 hours. Typical sample geometryand sizes for measurement are similar to, but not limited to, those usedfor characterizing oil well cements: 2 inch cubes; or 2 inch diametercylinders that are 4 inches in length; or 1 inch diameter cylinders thatare 2 inches in length; and other methods known to those skilled in theart of measuring “mechanical properties” of oil well cements. Forexample, the compressive strength may be determined by crushing thesamples in a compression-testing machine. The compressive strength iscalculated from the failure load divided by the cross-sectional arearesisting the load and is reported in units of pound-force per squareinch (psi). Compressive strengths may be determined in accordance withAPI RP 10B-2, Recommended Practice for Testing Well Cements, FirstEdition, July 2005.

As a specific example of a consolidation, when left in a well boreannulus (e.g., between a subterranean formation and the pipe stringdisposed in the subterranean formation or between the pipe string and alarger conduit disposed in the subterranean formation), the spacer fluidmay consolidate to develop static gel strength and/or compressivestrength. The consolidated mass formed in the well bore annulus may actto support and position the pipe string in the well bore and bond theexterior surface of the pipe string to the walls of the well bore or tothe larger conduit. The consolidated mass formed in the well boreannulus may also provide a substantially impermeable barrier to seal offformation fluids and gases and consequently also serve to mitigatepotential fluid migration. The consolidated mass formed in the well boreannulus may also protect the pipe string or other conduit fromcorrosion.

Embodiments of the spacer fluids of the present invention may have atransition time that is shorter than the transition time of cementcompositions subsequently introduced into the well bore. The term“transition time,” as used herein, refers to the time for a fluid toprogress from a static gel strength of about 100 lbf/100 ft² to about500 lbf/100 ft². By having a shorter transition time, the consolidatingspacer fluid can reduce or even prevent migration of gas in the wellbore, even if gas migrates through a subsequently introduced cementcomposition before it has developed sufficient gel strength to preventsuch migration. Gas and liquid migration can typically be prevented at astatic gel strength of 500 lbf/100 ft². By reducing the amount of gasthat can migrate through the well bore, the subsequently added cementcompositions can progress through its slower transition period withoutgas migration being as significant factor as the cement develops staticgel strength. Some embodiments of the consolidating spacer fluids mayhave a transition time (i.e., the time to progress from a static gelstrength of about 100 lbf/100 ft² to about 500 lbf/100 ft²) at well boreconditions of about 45 minutes or less, about 30 minutes or less, about20 minutes or less, or about 10 minutes or less. Embodiments of theconsolidating spacer fluids also quickly develop static gel strengths ofabout 100 lbf/100 ft² and about 500 lbf/100 ft², respectively, at wellbore conditions. The time for a fluid to a develop a static gel strengthof about 100 lbf/100 ft² is also referred to as the “zero gel time.” Forexample, the consolidating spacer fluids may have a zero gel time atwell bore condition of about 8 hours or less, and, alternatively, about4 hours or less. In some embodiments, the consolidating spacer fluidsmay have a zero gel time in a range of from about 0 minutes to about 4hours or longer. By way of further example, the consolidating spacerfluids may develop static gel strengths of about 500 lbf/100 ft² or moreat well bore conditions in a time of from about 10 minutes to about 8hours or longer. The preceding time for development of static gelstrengths are listed as being at well bore conditions. Those of ordinaryskill in the art will understand that particular well bore conditions(e.g., temperature, pressure, depth, etc.) will vary; however,embodiments of the spacer should meet these specific requirements atwell bore conditions. Static gel strength may be measured in accordancewith API Recommended Practice on Determining the Static Gel Strength ofCement Formations, ANSI/API Recommended Practice 10B-6.

Embodiments of the spacer fluids of the present invention may beprepared in accordance with any suitable technique. In some embodiments,the desired quantity of water may be introduced into a mixer (e.g., acement blender) followed by the dry blend. The dry blend may comprisethe CKD and additional solid additives, for example. Additional liquidadditives, if any, may be added to the water as desired prior to, orafter, combination with the dry blend. This mixture may be agitated fora sufficient period of time to form a base slurry. This base slurry maythen be introduced into the well bore via pumps, for example. In thefoamed embodiments, the base slurry may be pumped into the well bore,and a foaming agent may be metered into the base slurry followed byinjection of a gas, e.g., at a foam mixing “T,” in an amount sufficientto foam the base slurry thereby forming a foamed spacer fluid, inaccordance with embodiments of the present invention. After foaming, thefoamed spacer fluid may be introduced into a well bore. As will beappreciated by those of ordinary skill in the art, with the benefit ofthis disclosure, other suitable techniques for preparing spacer fluidsmay be used in accordance with embodiments of the present invention.

An example method of the present invention includes a method forevaluating a spacer fluid. The example method may comprise providing thespacer fluid for use in separating a drilling fluid and a cementcomposition in a well bore. Properties of the spacer fluid may then bemeasured to determine, for example, the consolidation efficiency for theparticular fluid. In some embodiments, the transition time and/or zerogel time of the spacer fluid may be measured. As previously described,the transition time is the time for the fluid to progress from a staticgel strength of about 100 lbf/100 ft² to about 500 lbf/100 ft², and thezero gel time is the time for the fluid to develop a static gel strengthof about 100 lbf/100 ft². Static gel strength may be measured inaccordance with API Recommended Practice on Determining the Static GelStrength of Cement Formations, ANSI/API Recommended Practice 10B-6. Insome embodiments, the compressive strength may be measured, which may bethe unconfined uniaxial compressive strength. Techniques for testing ofcompressive strength testing are described in more detail above. Thesemeasurements may be performed at a range of conditions, for example, tosimulate well bore conditions. In some embodiments, the transition timemay be measured at a temperature of from about 40° F. to about 300° F.and a pressure of from about 2,000 psi to about 10,000 psi. Thecompressive strengths may be determined, for example, at atmosphericconditions after the spacer fluid has been allowed to set in a waterbath at temperatures of from about 40° F. to 300° F. for a time of fromabout 24 hours to about 7 days. In some embodiments, the precedingevaluation may be performed for a set of sample spacer fluids, whereinembodiments further comprises selecting one of the sample spacer fluidsfrom the set based on the measured properties. Embodiments may furthercomprise preparing a spacer fluid based on the selected spacer fluid andusing the prepared spacer fluid in displacement of a drilling fluid froma well bore annulus.

An example method of the present invention includes a method ofenhancing rheological properties of a spacer fluid. The method maycomprise including CKD in a spacer fluid. The CKD may be included in thespacer fluid in an amount sufficient to provide a higher yield pointthan a first fluid. The higher yield point may be desirable, forexample, to effectively displace the first fluid from the well bore. Asused herein, the term “yield point” refers to the resistance of a fluidto initial flow, or representing the stress required to start fluidmovement. In an embodiment, the yield point of the spacer fluid at atemperature of up to about 180° F. is greater than about 5 lb/100 ft².In an embodiment, the yield point of the spacer fluid at a temperatureof up to about 180° F. is greater than about 10 lb/100 ft². In anembodiment, the yield point of the spacer fluid at a temperature of upto about 180° F. is greater than about 20 lb/100 ft². It may bedesirable for the spacer fluid to not thermally thin to a yield pointbelow the first fluid at elevated temperatures. Accordingly, the spacerfluid may have a higher yield point than the first fluid at elevatedtemperatures, such as 180° F. or bottom hole static temperature(“BHST”). In one embodiment, the spacer fluid may have a yield pointthat increases at elevated temperatures. For example, the spacer fluidmay have a yield point that is higher at 180° F. than at 80° F. By wayof further example. The spacer fluid may have a yield point that ishigher at BHST than at 80° F.

Another example method of the present invention includes a method ofdisplacing a first fluid from a well bore, the well bore penetrating asubterranean formation. The method may comprise providing a spacer fluidthat comprises CKD and water. The method may further compriseintroducing the spacer fluid into the well bore to displace at least aportion of the first fluid from the well bore. In some embodiments, thespacer fluid may displace the first fluid from a well bore annulus, suchas the annulus between a pipe string and the subterranean formation orbetween the pipe string and a larger conduit. In some embodiments, thespacer fluid may be characterized by having a higher yield point thanthe first fluid at 80° F. In some embodiments, the spacer fluid may becharacterized by having a higher yield point than the first fluid at130° F. In some embodiments, the spacer fluid may be characterized byhaving a higher yield point than the first fluid at 180° F.

In an embodiment, the first fluid displaced by the spacer fluidcomprises a drilling fluid. By way of example, the spacer fluid may beused to displace the drilling fluid from the well bore. In addition todisplacement of the drilling fluid from the well bore, the spacer fluidmay also remove the drilling fluid from the walls of the well bore. Thedrilling fluid may include, for example, any number of fluids, such assolid suspensions, mixtures, and emulsions. In some embodiments, thedrilling fluid may comprise an oil-based drilling fluid. An example of asuitable oil-based drilling fluid comprises an invert emulsion. In someembodiments, the oil-based drilling fluid may comprise an oleaginousfluid. Examples of suitable oleaginous fluids that may be included inthe oil-based drilling fluids include, but are not limited to,α-olefins, internal olefins, alkanes, aromatic solvents, cycloalkanes,liquefied petroleum gas, kerosene, diesel oils, crude oils, gas oils,fuel oils, paraffin oils, mineral oils, low-toxicity mineral oils,olefins, esters, amides, synthetic oils (e.g., polyolefins),polydiorganosiloxanes, siloxanes, organosiloxanes, ethers, acetals,dialkylcarbonates, hydrocarbons, and combinations thereof. Additionalsteps in embodiments of the method may comprise introducing a pipestring into the well bore, introducing a cement composition into thewell bore with the spacer fluid separating the cement composition andthe first fluid. In an embodiment, the cement composition may be allowedto set in the well bore. The cement composition may include, forexample, cement and water.

Another example method of the present invention includes a method ofseparating fluids in a well bore, the well bore penetrating asubterranean formation. The method may comprise introducing a spacerfluid into the well bore, the well bore having a first fluid disposedtherein. The spacer fluid may comprise, for example, CKD and water. Themethod may further comprise introducing a second fluid into the wellbore with the spacer fluid separating the first fluid and the secondfluid. In an embodiment, the first fluid comprises a drilling fluid andthe second fluid comprises a cement composition. By way of example, thespacer fluid may prevent the cement composition from contacting thedrilling fluid. The cement composition may be foamed or unfoamed asdesired for a particular application. In an embodiment, the cementcomposition comprises cement kiln dust, water, and optionally ahydraulic cementitious material. A variety of hydraulic cements may beutilized in accordance with the present invention, including, but notlimited to, those comprising calcium, aluminum, silicon, oxygen, iron,and/or sulfur, which set and harden by reaction with water. Suitablehydraulic cements include, but are not limited to, Portland cements,pozzolana cements, gypsum cements, high alumina content cements, slagcements, silica cements, and combinations thereof. In certainembodiments, the hydraulic cement may comprise a Portland cement. Insome embodiments, the Portland cements that are suited for use in thepresent invention are classified as Classes A, C, H, and G cementsaccording to American Petroleum Institute, API Specification forMaterials and Testing for Well Cements, API Specification 10, Fifth Ed.,Jul. 1, 1990. The spacer fluid may also remove the drilling fluid,dehydrated/gelled drilling fluid, and/or filter cake solids from thewell bore in advance of the cement composition. Embodiments of thespacer fluid may improve the efficiency of the removal of these andother compositions from the well bore. Removal of these compositionsfrom the well bore may enhance bonding of the cement composition tosurfaces in the well bore. In an additional embodiment, at least aportion of used and/or unused CKD containing spacer fluid are includedin the cement composition that is placed into the well and allowed toset.

In some embodiments, at least a portion of the spacer fluid may be leftin the well bore such that the spacer fluid consolidates in the wellbore. In some embodiments, the spacer fluid may consolidate to form anannular sheath of a rigid solid. The annular sheath of rigid solid maybond the exterior surface of the pipe string to the walls of the wellbore or to the larger conduit. An example method of the presentinvention may further include measuring the consolidation of the spacerfluid. This measurement may also include a measurement of the integrityof the bond formed between the consolidated spacer fluid and theexterior wall of the pipe string and/or between the consolidated spacerfluid and the formation or larger conduit disposed in the well bore. Insome embodiments, data may be collected corresponding to the integrityof this bond, and the data may be recorded on a log, commonly referredto as a “bond long.” The bond log may be used to, for example, analyzethe consolidation properties of the spacer fluid in the well bore.Accordingly, embodiments may include running a cement bond log on atleast the portion of the well bore containing the consolidated spacerfluid. The cement bond log for the settable spacer fluid may be obtainedby any method used to measure cement integrity without limitation. Insome embodiments, a tool may be run into the well bore on a wirelinethat can detect the bond of the set spacer fluid to the pipe stringand/or the formation (or larger conduit). An example of a suitable toolincludes a sonic tool.

In some embodiments, it may be desirable to detect the subterraneanlocation or locations of the consolidating spacer fluid or the cementcomposition after they have been introduced into the well bore. Inaccordance with present embodiments, a boundary between theconsolidating spacer fluid and the cement composition may be determined.It should be understood that the determine boundary may not be a preciselocation in the well bore, but may extend over a length about 1 feet ormore, about 2 feet or more, about 5 feet or more, or about 10 feet ormore. As an example, in a primary cementing operation where a conduit,such as a casing or liner, is to be cemented in place in a well bore, aconsolidating spacer fluid may be pumped downhole through the conduitand then upwardly into the annulus between the conduit and the walls ofthe well bore. Likewise, the cement composition would be pumped in asimilar manner after the consolidating spacer fluid. Once the cementcomposition has been placed in the annulus, it may be important toverify that the cement composition has uniformly filled the annulus overthe entire length of casing or liner being cemented. For example,operators may find it difficult to distinguish between the top of thecement composition and the bottom of the consolidating spacer fluidsince any part of the consolidating spacer fluid left in the well borewould consolidate into a hardened mass. In these embodiments, the atleast a portion of the cement composition may comprise a taggingmaterial. For example, the first portion of the cement compositionintroduced into the well bore may comprise the tagging material. Thetagging material may be added to the portion of the cement compositionas it is being prepared by surface equipment. For example, the taggingmaterial may be blended with the lead cement as a dry blend, addedduring the cement mixing phase of the cementing operation, or placed inthe cement mix water for the lead cement. In some embodiments, thetagging material may be added on-the-fly. The term “on-the-fly” is usedherein to mean that a flowing stream is continuously introduced intoanother flowing stream so that the streams are combined and mixed whilecontinuing to flow as a single stream as part of the on-going treatment.The tagging material should allow the use of typical well bore loggingdevices to determine the location of the top of cement when aconsolidating spacer fluid is used. In alternative embodiments, thetagging material may be added to the consolidating spacer fluid insteadof the cement composition. The tagging material may be added, forexample, to the trailing portion of the consolidating spacer fluid. Thetagging material may be added to the consolidating spacer fluid as it isbeing prepared by surface equipment. The tagging material allows the useof well bore logging devices to determine the location of the top ofcement and the bottom of the consolidating spacer fluid when aconsolidating spacer fluid is used to treat the well bore.

Tagging materials may comprise relatively inert materials and/or alsomaterials that are thermal neutron absorbing materials. Thermal neutronabsorbing materials may comprise any element which has a thermal neutronabsorbing capability of a magnitude such that differences in thebackscattered thermal neutrons before and after a treatment fluid orcement composition containing the material are introduced into a wellbore can be detected. However, certain elements which have a higherthermal neutron absorbing capacity than others may be used in someembodiments. Exemplary embodiments may comprise thermal neutronabsorbing materials for use with neutron logging devices, however,tagging materials may comprise a variety of materials including thoseknown in the art. Exemplary embodiments include the use of taggingmaterials that are inert to the chemical and physical properties of thecement composition. In some embodiments, these tagging materials shouldcause no significant changes in the conventional, desirable cementproperties of cement composition, such properties may include density,rheology, pumping time, fluid loss, static gel strength, permeability,etc. Additionally, materials which themselves are not environmentallydestructive are used in particular embodiments. Compounds such as boroncarbide or cadmium hydroxide are examples of relatively inert materialswith the properties described above and are also examples of thermalneutron absorbing materials that may be used with neutron loggingdevices. Both boron carbide and cadmium hydroxide are completelyinsoluble in aqueous systems, however soluble tagging materials may beadequate for some applications. Multiple tagging materials may be usedin a single application and in combination with other tagging materials.Tagging materials may comprise a dry powder. Dry powders, such as boroncarbide or cadmium hydroxide, provide easy application of the taggingmaterial to the leading portion of cement composition cement, forexample, in a downhole tub (DH) or a recirculating mixer tub (RCM) suchas in an RCM® IIIc mixing system available from Halliburton EnergyServices. Additionally, liquid forms of tagging materials may also beadequate. In alternative embodiments, the dry powder or liquid forms ofthe tagging material may be added to the consolidating spacer fluid inlieu of the cement composition. The addition of the tagging materials tothe consolidating spacer fluid may occur at any time in the preparationor use of the consolidating spacer fluid. Tagging materials may be addedto the cement composition or the consolidating spacer fluid in additionto other cement or consolidating spacer fluid additives. In embodiments,only enough tagging material is added to produce a verifiable signalwith a well bore logging device, such as a neutron logging device.

In some embodiments, the tagging materials may be added to the at leasta portion of the cement composition in any concentration to obtain avalid and/or verifiable reading. In some embodiments the taggingmaterials may be added to the portion of the cement composition in aconcentration of about 0.1% to about 0.5%, such as in a range of about0.1%, about 0.2%, about 0.3%, about 0.5%, about 1%, about 2%, about 3%etc., by weight of the cement. In some embodiments, the tagging materialmay be added to a first portion of the cement composition that isintroduced into the well bore. For example, the tagging material may beadded to an upper section of the lead cement or slurry, which istypically a top section of the cement intended to cover upper portionsof the well bore annulus. In some embodiments, the lead cement may covera section in the well bore annulus between the consolidating spacerfluid and the tail cement or slurry that has a length of about 50 feet,about 100 feet, or the entire length of the lead cement slurry.Embodiments of the tagging material may be added to a portion of thecement composition having a length in the well bore annulus that isabout 20 feet or less, alternatively about 10 feet or less, andalternatively about 5 feet or less. In alternative embodiments, thetagging materials may be added to at least a portion of theconsolidating spacer fluid in any concentration to obtain a valid and/orverifiable reading. For example, the tagging materials may be added to atrailing portion of the consolidating spacer fluid. In some embodimentsthe tagging materials be added to the consolidating spacer fluids in aconcentration of about 0.1% to about 0.5%, such as in a range of about0.1%, about 0.2%, about 0.3%, about 0.5%, about 1%, about 2%, about 3%etc., by weight of the consolidating spacer fluid.

As shown in FIG. 1, in embodiments of a well bore cementing system 1,the cement composition may be mixed in mixing equipment 5, such as amixer or recirculating tub and then pumped via pump 10 to the well bore.In some embodiments, mixing equipment 5 and pump 10 may be used toseparately prepare and deliver the consolidating spacer fluid to thewell bore. As illustrated in FIG. 2, the consolidated spacer fluid andthe cement composition comprising tagging materials may be pumped intothe casing 15 in the direction shown by the arrows. The consolidatedspacer fluid and the cement composition comprising tagging materials maybe pumped through the casing 15 and through or into the subterraneanformation 20 until they reach the end point are pushed upward into theannulus 25 which resides between the pipe casing 15 and walls 30 of wellbore 35.

As shown in FIG. 3, in embodiments of a consolidated spacer fluid system40, a cement composition 45 may be pumped downhole so that the cementcomposition 45 is disposed between the walls 30 of the well bore 35 andthe casing 15. The first portion 50 of the cement composition 45 maycomprise the tagging material. The tagging material may be added duringthe process of preparing or pumping the first portion 50 of the cementcomposition 45. As illustrated, the consolidating spacer fluid 55 may bedisposed in the well bore 35 above the cement composition 45. Theconsolidating spacer fluid 55 may be disposed between the walls 30 ofthe well bore 35 and the subterranean formation 20. In accordance withpresent embodiment, a well bore log (e.g., a cement bond log) may beprepared that may show where the tagging materials are located in thefirst portion 50 of the cement composition 45. This log can allowoperators to determine where the bottom of the consolidating spacerfluid 55 is located relative to the top of the cement composition 45.

The exemplary embodiments of the consolidated spacer fluids includingthose embodiments comprising tagging materials disclosed herein maydirectly or indirectly affect one or more components or pieces ofequipment associated with the preparation, delivery, recapture,recycling, reuse, and/or disposal of the disclosed embodiments of theconsolidated spacer fluids. For example, the disclosed embodiments ofthe consolidated spacer fluids may directly or indirectly affect one ormore mixers, related mixing equipment, mud pits, storage facilities orunits, composition separators, heat exchangers, sensors, gauges, pumps,compressors, and the like used generate, store, monitor, regulate,and/or recondition the exemplary embodiments of the consolidated spacerfluids. The disclosed embodiments of the consolidated spacer fluids mayalso directly or indirectly affect any transport or delivery equipmentused to convey the embodiments of the consolidated spacer fluids to awell site or downhole such as, for example, any transport vessels,conduits, pipelines, trucks, tubulars, and/or pipes used tocompositionally move the embodiments of the consolidated spacer fluidsfrom one location to another, any pumps, compressors, or motors (e.g.,topside or downhole) used to drive the embodiments of the consolidatedspacer fluids into motion, any valves or related joints used to regulatethe pressure or flow rate of the embodiments of the consolidated spacerfluids, and any sensors (i.e., pressure and temperature), gauges, and/orcombinations thereof, and the like. The disclosed embodiments of theconsolidated spacer fluids may also directly or indirectly affect thevarious downhole equipment and tools that may come into contact with thecement compositions/additives such as, but not limited to, well borecasing, well bore liner, completion string, insert strings, drillstring, coiled tubing, slickline, wireline, drill pipe, drill collars,mud motors, downhole motors and/or pumps, cement pumps, surface-mountedmotors and/or pumps, centralizers, turbolizers, scratchers, floats(e.g., shoes, collars, valves, etc.), logging tools and relatedtelemetry equipment, actuators (e.g., electromechanical devices,hydromechanical devices, etc.), sliding sleeves, production sleeves,plugs, screens, filters, flow control devices (e.g., inflow controldevices, autonomous inflow control devices, outflow control devices,etc.), couplings (e.g., electro-hydraulic wet connect, dry connect,inductive coupler, etc.), control lines (e.g., electrical, fiber optic,hydraulic, etc.), surveillance lines, drill bits and reamers, sensors ordistributed sensors, downhole heat exchangers, valves and correspondingactuation devices, tool seals, packers, cement plugs, bridge plugs, andother well bore isolation devices, or components, and the like.

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, thescope of the invention. In the following examples, concentrations aregiven in weight percent of the overall composition.

EXAMPLE 1

Sample spacer fluids were prepared to evaluate the rheologicalproperties of spacer fluids containing CKD. The sample spacer fluidswere prepared as follows. First, all dry components (e.g., CKD, fly ash,bentonite, FWCA, etc.) were weighed into a glass container having aclean lid and agitated by hand until blended. Tap water was then weighedinto a Waring blender jar. The dry components were then mixed into thewater with 4,000 rpm stirring. The blender speed was then increased to12,000 rpm for about 35 seconds.

Sample Spacer Fluid No. 1 was an 11 pound per gallon slurry thatcomprised 60.62% water, 34.17% CKD, 4.63% fly ash, and 0.58% free watercontrol additive (WG-17™ solid additive).

Sample Spacer Fluid No. 2 was an 11 pound per gallon slurry thatcomprised 60.79% water, 30.42% CKD, 4.13% fly ash, 0.17% free watercontrol additive (WG-17™ solid additive), 3.45% bentonite, and 1.04%Econolite™ additive.

Rheological values were then determined using a Fann Model 35Viscometer. Dial readings were recorded at speeds of 3, 6, 100, 200, and300 with a B1 bob, an R1 rotor, and a 1.0 spring. The dial readings,plastic viscosity, and yield points for the spacer fluids were measuredin accordance with API Recommended Practices 10B, Bingham plastic modeland are set forth in the table below. The abbreviation “PV” refers toplastic viscosity, while the abbreviation “YP” refers to yield point.

TABLE 1 Sample Temp. Viscometer RPM PV YP (lb/ Fluid (° F.) 300 200 1006 3 (cP) 100 ft²⁾ 1 80 145 127 90 24 14 113.3 27.4 180 168 143 105 26 15154.5 30.3 2 80 65 53 43 27 22 41.1 26.9 180 70 61 55 22 18 51.6 25.8

The thickening time of the Sample Spacer Fluid No. 1 was also determinedin accordance with API Recommended Practice 10B at 205° F. Sample SpacerFluid No. 1 had a thickening time of more than 6:00+ hours.

Accordingly, the above example illustrates that the addition of CKD to aspacer fluid may provide suitable properties for use in subterraneanapplications. In particular, the above example illustrates, inter alia,that CKD may be used to provide a spacer fluid that may not exhibitthermal thinning with the spacer fluid potentially even having a yieldpoint that increases with temperature. For example, Sample Spacer FluidNo. 2 had a higher yield point at 180° F. than at 80° F. In addition,the yield point of Sample Spacer Fluid No. 1 had only a slight decreaseat 180° F. as compared to 80° F. Even further, the example illustratesthat addition of CKD to a spacer fluid may provide a plastic viscositythat increases with temperature.

EXAMPLE 2

Additional sample spacer fluids were prepared to further evaluate therheological properties of spacer fluids containing CKD. The samplespacer fluids were prepared as follows. First, all dry components (e.g.,CKD, fly ash) were weighed into a glass container having a clean lid andagitated by hand until blended. Tap water was then weighed into a Waringblender jar. The dry components were then mixed into the water with4,000 rpm stirring. The blender speed was then increased to 12,000 rpmfor about 35 seconds.

Sample Fluid No. 3 was a 12.5 pound per gallon fluid that comprised47.29% water and 52.71% CKD.

Sample Fluid No. 4 was a 12.5 pound per gallon fluid that comprised46.47% water, 40.15% CKD, and 13.38% fly ash.

Sample Fluid No. 5 was a 12.5 pound per gallon fluid that comprised45.62% water, 27.19% CKD, and 27.19% fly ash.

Sample Fluid No. 6 was a 12.5 pound per gallon fluid that comprised44.75% water, 13.81% CKD, and 41.44% fly ash.

Sample Fluid No. 7 (comparative) was a 12.5 pound per gallon fluid thatcomprised 43.85% water, and 56.15% fly ash.

Rheological values were then determined using a Fann Model 35Viscometer. Dial readings were recorded at speeds of 3, 6, 30, 60, 100,200, 300, and 600 with a B1 bob, an R1 rotor, and a 1.0 spring. The dialreadings, plastic viscosity, and yield points for the spacer fluids weremeasured in accordance with API Recommended Practices 10B, Binghamplastic model and are set forth in the table below. The abbreviation“PV” refers to plastic viscosity, while the abbreviation “YP” refers toyield point.

TABLE 2 CKD- Sample Fly YP Spacer Ash Temp. Viscometer RPM PV (lb/ FluidRatio (° F.) 600 300 200 100 60 30 6 3 (cP) 100 ft²⁾ 3 100:0  80 33 2320 15 13 12 8 6 12 11 130 39 31 27 23 22 19 16 11 12 19 180 66 58 51 4740 38 21 18 16.5 41.5 4 75:25 80 28 22 19 15 14 11 8 6 10.5 11.5 130 3928 25 21 19 16 14 11 10.5 17.5 180 51 39 36 35 31 26 16 11 6 33 5 50:5080 20 11 8 6 5 4 4 3 7.5 3.5 130 21 15 13 10 9 8 6 5 7.5 7.5 180 25 2017 14 13 12 7 5 9 11 6 25:75 80 16 8 6 3 2 1 0 0 7.5 0.5 130 15 8 6 4 32 1 1 6 2 180 15 9 7 5 4 4 2 2 6 3 7  0:100 80 16 7 5 3 1 0 0 0 6 1(Comp.) 130 11 4 3 1 0 0 0 0 4.5 −0.5 180 8 3 2 0 0 0 0 0 4.5 −1.5

Accordingly, the above example illustrates that the addition of CKD to aspacer fluid may provide suitable properties for use in subterraneanapplications. In particular, the above example illustrates, inter alia,that CKD may be used to provide a spacer fluid that may not exhibitthermal thinning with the spacer fluid potentially even having a yieldpoint that increases with temperature. In addition, as illustrated inTable 2 above, higher yield points were observed for spacer fluids withhigher concentrations of CKD.

EXAMPLE 3

A sample spacer fluid containing CKD was prepared to compare therheological properties of a spacer fluid containing CKD with anoil-based drilling fluid. The sample spacer fluid was prepared asfollows. First, all dry components (e.g., CKD, fly ash, bentonite, etc.)were weighed into a glass container having a clean lid and agitated byhand until blended. Tap water was then weighed into a Waring blenderjar. The dry components were then mixed into the water with 4,000 rpmstirring. The blender speed was then increased to 12,000 rpm for about35 seconds.

Sample Spacer Fluid No. 8 was an 11 pound per gallon slurry thatcomprised 60.79% water, 30.42% CKD, 4.13% fly ash, 0.17% free watercontrol additive (WG-17™ solid additive), 3.45% bentonite, and 1.04%Econolite™ additive.

The oil-based drilling fluid was a 9.1 pound per gallon oil-based mud.

Rheological values were then determined using a Farm Model 35Viscometer. Dial readings were recorded at speeds of 3, 6, 100, 200, and300 with a B1 bob, an R1 rotor, and a 1.0 spring. The dial readings,plastic viscosity, and yield points for the spacer fluid and drillingfluid were measured in accordance with API Recommended Practices 10B,Bingham plastic model and are set forth in the table below. Theabbreviation “PV” refers to plastic viscosity, while the abbreviation“YP” refers to yield point. The abbreviation “OBM” refers to oil-basedmud.

TABLE 3 Sample Temp. Viscometer RPM PV YP (lb/ Fluid (° F.) 300 200 1006 3 (cP) 100 ft²⁾ 8 80 59 50 39 22 15 42 21.2 180 82 54 48 16 13 65.3 17OBM 80 83 64 41 11 10 74.6 12.1 180 46 35 23 10 10 36.7 10.5

Accordingly, the above example illustrates that the addition of CKD to aspacer fluid may provide suitable properties for use in subterraneanapplications. In particular, the above example illustrates, inter alfa,that CKD may be used to provide a spacer fluid with a yield point thatis greater than a drilling fluid even at elevated temperatures. Forexample, Sample Spacer Fluid No. 8 has a higher yield point at 180° F.than the oil-based mud.

EXAMPLE 4

A foamed spacer fluid (Sample Fluid 9) was prepared that comprised CKD.First, a base slurry was prepared that had a density of 10 ppg andcomprised CKD, a free water control additive (0.7% by weight of CKD), alightweight additive (4% by weight of CKD), and fresh water (32.16gallons per 94-pound sack of CKD). The free water control additive wasSA-1015™ suspending aid. The lightweight additive was ECONOLITE™additive. Next, a foaming agent (FOAMER™ 760 foamer/stabilizer) in anamount of 2% bvow was added, and the base slurry was then mixed in afoam blending jar for 4 seconds at 12,000 rpm. The resulting foamedspacer fluid had a density of 8.4 ppg. The “sink” of the resultantfoamed spacer fluid was then measured using a free fluid test procedureas specified in API Recommended Practice 10B. However, rather thanmeasuring the free fluid, the amount of “sink” was measured after thefoamed spacer fluid remained static for a period of 2 hours. The foamedspacer fluid was initially at 200° and cooled to ambient temperatureover the 2-hour period. The measured sink for this foamed spacer fluidwas 5 millimeters.

EXAMPLE 5

Another foamed spacer fluid (Sample Fluid 10) was prepared thatcomprised CKD. First, a base slurry was prepared that had a density of10.5 ppg and comprised CKD, a free water control additive (0.6% byweight of CKD), a lightweight additive (4% by weight of CKD), and freshwater (23.7 gallons per 94-pound sack of CKD). The free water controladditive was SA1015™ suspending aid. The lightweight additive wasECONOLITE™ additive. Next, a foaming agent (a hexyleneglycol/cocobetaine blended surfactant) in an amount of 2% bvow wasadded, and the base slurry was then mixed in a foam blending jar for 6seconds at 12,000 rpm. The resulting foamed spacer fluid had a densityof 8.304 ppg. The resultant foamed spacer fluid had a sink of 0millimeters, measured as described above for Example 4.

EXAMPLE 6

The following series of tests were performed to determine thecompressive strength of consolidating spacer fluids. Twenty-two samples,labeled sample fluids 11-32 in the table below, were prepared having adensity of 12.5 ppg using various concentrations of additives. Theamount of these additives in each sample fluid are indicated in thetable below with “% by weight” indicating the amount of the particularcomponent by weight of Additive 1+Additive 2. The abbreviation “gal/sk”in the table below indicates gallons of the particular component per94-pound sack of Additive 1 and Additive 2.

The CKD used was supplied by Holcim (US) Inc., from Ada, Okla. The shaleused was supplied by Texas Industries, Inc., from Midlothian, Tex. Thepumice used was either DS-200 or DS-300 lightweight aggregate availablefrom Hess Pumice Products, Inc. The silica flour used was SSA-1™ cementadditive, from Halliburton Energy Services, Inc. The course silica flourused was SSA-2™ course silica flour, from Halliburton Energy Services,Inc. The metakaolin used was MetaMax® metakaolin, from BASF. Theamorphous silica used was SILICALITE™ cement additive, from HalliburtonEnergy Services, Inc. The perlite used was supplied by Hess PumiceProducts, Inc. The slag used was supplied by LaFarge North America. ThePortland cement Interground with pumice was FineCem™ cement, fromHalliburton Energy Services, Inc. The fly ash used was POZMIX® cementadditive, from Halliburton Energy Services, Inc. The micro-fine cementused was MICRO MATRIX® having an average particle size of 7.5 microns,from Halliburton Energy Services, Inc. The rice husk ash used wassupplied by Rice Hull Specialty Products, Stuttgart, Ark. The biopolymerused was supplied by CP Kelco, San Diego, Calif. The barite used wassupplied by Baroid Industrial Drilling Products. The latex used wasLatex 3000™ cement additive from Halliburton Energy Services, Inc. Theground rubber used was LIFECEM™ 100 from Halliburton Energy Services,Inc. The nano-clay used was supplied by Nanocor Inc. The set retarderused was SCR100™ cement retarder, from Halliburton Energy Services, Inc.SCR1100™ cement retarder is a copolymer of acrylic acid and2-acrylamido-2-methylpropane sulfonic acid.

After preparation, the sample fluids were allowed to cure for seven daysin a 2″ by 4″ metal cylinder that was placed in a water bath at 180° F.to form set cylinders. Immediately after removal from the water bath,destructive compressive strengths were determined using a mechanicalpress in accordance with API RP 10B-2. The results of this test are setforth below.

TABLE 4 Additive Additive Additive Cement 7-Day #1 #2 #3 Set Comp.Sample Water % by % by % by Retarder Strength Fluid gal/sk Type wt Typewt Type Wt % by wt PSI 11 5.72 CKD 50 Shale 50 — — 0 510 12 4.91 Pumice50 Lime 50 — — 1 646 DS- 200 13 5.88 CKD 50 Silica Flour 50 — — 0 288 146.05 CKD 50 Metakaolin 50 — — 0 104 15 5.71 CKD 50 Amorphous 50 — — 1251 Silica 16 5.13 CKD 50 Perlite 50 — — 0 1031 17 5.4 CKD 50 Lime 50 —— 0 58 18 5.49 CKD 50 Pumice DS- 50 — — 0 624 200 19 6.23 CKD 50 Slag 50— — 0 587 20 5.88 CKD 50 Course 50 — — 0 1018 Silica Flour 21 6.04 CKD50 Portland 50 — — 1 1655 Cement Interground with Pumice 22 5.63 CKD 50Fly Ash 50 — — 0 870 23 5.49 CKD 50 Pumice DS- 50 — — 0 680 325 24 5.03Fly 50 Lime 50 — — 1 170 Ash 25 5.65 Slag 50 Lime 50 — — 1 395 26 6.36CKD 50 Micro-fine 50 — — 2 788 cement 27 6.08 CKD 80 Rice Husk 20 — — 1203 Ash 28 5.42 CKD 50 Biopolymer 50 — — 1 265 29 7.34 CKD 50 Barite 50— — 0 21 30 4.02 CKD 100 — — Latex 2 1 164.6 31 2.71 CKD 100 — — Ground10  1 167.6 Rubber 32 6.15 CKD 100 — — Nano- 2 0 102.5 Clay

Accordingly, the above example illustrates that a consolidating spacerfluid comprising CKD may be capable of consolidation. For example, 7-daycompressive strengths of 1000 psi or even higher were observed forcertain sample slurries.

EXAMPLE 7

The following series of tests were performed to evaluate the thickeningtimes of consolidating spacer fluids. For this example, the thickeningtimes for Sample Fluids 11-32 from Example 6 were determined. Asindicated below, the compositions for Samples Fluids 11-32 were the sameas from Example 6 except the concentration of the cement set retarderwas adjusted for certain samples. The thickening time, which is the timerequired for the compositions to reach 70 Bearden units of consistency,was determined for each fluid at 230° F. in accordance with API RP10B-2. The results of this test are set forth below.

TABLE 5 Additive Additive Additive Cement #1 #2 #3 Set Thickening SampleWater % by % by % by Retarder Time Fluid gal/sk Type wt Type wt Type Wt% by wt hr:min 11 5.72 CKD 50 Shale 50 — — 1 11:04  12 4.91 Pumice 50Lime 50 — — 1 0:30 DS- 200 13 5.88 CKD 50 Silica Flour 50 — — 1 3:31 146.05 CKD 50 Metakaolin 50 — — 1 3:13 15 5.71 CKD 50 Amorphous 50 — — 12:15 Silica 16 5.13 CKD 50 Perlite 50 — — 1 7:30 17 5.4 CKD 50 Lime 50 —— 1 2:42 18 5.49 CKD 50 Pumice DS- 50 — — 1 10:00  200 19 6.23 CKD 50Slag 50 — — 1 8:08 20 5.88 CKD 50 Course 50 — — 1 20 hr+ Silica Flour 216.04 CKD 50 Portland 50 — — 1 5:58 Cement Interground with Pumice 225.63 CKD 50 Fly Ash 50 — — 1 12 hr+ 23 5.49 CKD 50 Pumice DS- 50 — — 17:30 325 24 5.03 Fly 50 Lime 50 — — 1 3:32 Ash 25 5.65 Slag 50 Lime 50 —— 1 4:05 26 6.36 CKD 50 Micro-fine 50 — — 2 1:30 cement 27 6.08 CKD 80Rice Husk 20 — — 1 30 hr+ Ash 28 5.42 CKD 50 Biopolymer 50 — — 1 1:35 297.34 CKD 50 Barite 50 — — 1 18 hr+ 30 4.02 CKD 100 — — Latex 2 1 1:10 312.71 CKD 100 — — Ground 10  1 20 hr+ Rubber 32 6.15 CKD 100 — — Nano- 20 54:00  Clay

Accordingly, the above example illustrates that a settable spacer fluidmay have acceptable thickening times for certain applications.

EXAMPLE 8

The following series of tests were performed to evaluate the rheologicalproperties of consolidating spacer fluids. For this example, therheological properties of Sample Fluids 11-32 were determined. Therheological values were determined using a Fann Model 35 Viscometer.Dial readings were recorded at speeds of 3, 6, 30, 60, 100, 200, 300,and 600 with a B1 bob, an R1 rotor, and a 1.0 spring. An additionalsample was used for this specific test. It is Sample Fluid 33 andcomprised barite and 0.5% of a suspending agent by weight of the barite.The suspending agent was SA™-1015, available from Halliburton EnergyServices, Inc. The water was included in an amount sufficient to providea density of 12.5 ppg. Sample 33's rheological properties were measuredtwice at two different temperatures and the values per temperature wereaveraged to present the data shown below. Temperature is measured indegrees Fahrenheit. The results of this test are set forth below.

TABLE 6 Additive Additive Additive #1 #2 #3 Sample % by % by % byViscometer RPM Fluid Type wt Type wt Type wt Temp. 300 200 100 60 30 6 3600 11 CKD 50 Shale 50 — — 80 29 21 14 11 9 6 5 39 12 Pumice 50 Lime 50— — 80 24 17 9 6 5 2 1 48 DS-200 13 CKD 50 Silica Flour 50 — — 80 16 128 6 5 4 3 24 14 CKD 50 Metakaolin 50 — — 80 36 28 19 15 12 9 8 64 15 CKD50 Amorphous 50 — — 80 31 24 18 14 12 10 9 49 Silica 16 CKD 50 Perlite50 — — 80 40 34 27 23 20 15 9 61 17 CKD 50 Lime 50 — — 80 46 41 34 30 2716 11 65 18 CKD 50 Pumice DS- 50 — — 80 23 19 14 11 9 7 6 40 200 19 CKD50 Slag 50 — — 80 23 20 14 11 9 6 5 41 20 CKD 50 Course 50 — — 80 27 1912 9 7 4 3 64 Silica Flour 21 CKD 50 Portland 50 — — 80 15 10 7 5 3 2 118 Cement Interground with Pumice 22 CKD 50 Fly Ash 50 — — 80 12 9 6 4 32 1 21 23 CKD 50 Pumice DS- 50 — — 80 39 32 24 21 17 12 7 57 325 24 FlyAsh 50 Lime 50 — — 80 12 9 6 4 3 2 2 24 25 Slag 50 Lime 50 — — 80 15 105 3 2 1 1 23 26 CKD 50 Micro-fine 50 — — 80 10 7 4 3 2 1 0 14 cement 27CKD 80 Rice Husk 20 — — 80 24 15 9 7 5 3 2 41 Ash 28 CKD 50 Biopolymer50 — — 80 175 111 53 31 15 4 3 220 29 CKD 50 Barite 50 — — 80 48 40 3026 22 15 13 2 30 CKD 100 — — Latex 2 80 48 39 28 23 19 17 15 82 31 CKD100 — — Ground 10 80 65 56 42 40 39 30 22 105 Rubber 32 CKD 100 — —Nano- 2 80 22 18 12 10 8 6 5 37 Clay 33 Barite 100 — — SA ™- 0.5 80 4136.5 30.5 28 25.5 20.5 18.5 NA 1015 33 Barite 100 — — SA ™- 0.5 180 3835.5 32 30 28 23.5 22 NA 1015

Accordingly, the above example indicates that a consolidating spacerfluid may have acceptable rheological properties for a particularapplication.

EXAMPLE 9

The following series of tests were performed to further evaluate thecompressive strength of consolidating spacer fluids. Ten samples,labeled Sample Fluids 34-43 in the table below were prepared, having adensity of 13 ppg using various concentrations of additives. The amountof these additives in each sample are indicated in the table below with“% by weight” indicating the amount of the particular component byweight of the dry solids, which is the CKD, the Portland cement, thecement accelerator, the fly ash, and/or the lime. The abbreviation“gal/sk” in the table below indicates gallons of the particularcomponent per 94-pound sack of the dry solids.

The CKD used was Mountain CKD from Laramie Wyo., except for Sample Fluid43 which used CKD from Holcim (US) Inc., Ada, Okla. The Portland cementused in Sample Fluids 34 and 35 was CEMEX Type 3 Portland cement, fromCEMEX USA. The cement accelerator used in Sample Fluid 34 was CAL-SEAL™accelerator, from Halliburton Energy Services Inc. CAL-SEAL™ Acceleratoris gypsum. The Class F fly ash used in Slurries 37-41 was from CoalCreek Station. The Class C fly ash used in Slurries 36 was from LaFargeNorth America.

After preparation, the samples were allowed to cure for twenty-four orforty-eight hours in a 2″ by 4″ metal cylinder that was placed in awater bath at 160° F. to form set cylinders. For certain samples,separate cylinders were cured for twenty-four hours and forty-eighthours. Immediately after removal from the water bath, destructivecompressive strengths were determined using a mechanical press inaccordance with API RP 10B-2. The results of this test are set forthbelow.

TABLE 7 Class Class Cement F Fly C Fly 24-Hr 48-Hr CKD % Portland Accel.Ash Ash Lime Comp. Comp. Sample Water by Cement % by % by % by % byStrength Strength Fluid gal/sk wt % by wt wt wt wt wt PSI PSI 34 8.75 8510 5 0 0 0 73.4 — 35 8.75 90 10 0 0 0 0 99.8 — 36 8.14 70 0 0 0 30 0 210— 37 8.25 70 0 0 25 0 5 388 — 38 8.20 75 0 0 21 0 4 300 784 39 8.27 80 00 17.5 0 2.5 224 641 40 9.61 70 0 0 25 0 5 219 567 41 11.5 70 0 0 25 0 5165 369 42 5.12 100 0 0 0 0 0 36.2 — 43 5.12 100 0 0 0 0 0 60.8 —

Accordingly, the above example illustrates that a consolidating spacerfluid may have acceptable compressive strengths for certainapplications.

EXAMPLE 10

The following series of tests were performed to evaluate the static gelstrength development of consolidating spacer fluids. Two samples,labeled Sample Fluids 44 and 45 were prepared having a density of 11 and13.5 ppg respectively using various concentrations of additives. Thecomponent concentrations of each sample are as follows:

For Sample Fluid 44, the sample comprised a blend of CKD (80% byweight), fly ash (16% by weight) and hydrated lime (4% by weight). Thesample also comprised a suspending aid in an amount of 0.4% by weight ofthe blend. Sufficient water was included in the sample to provide adensity of 11 ppg. The CKD used was from Holcim (US) Inc., Ada, Okla.The fly ash used was POZMIX® cement additive, from Halliburton EnergyServices, Inc. The suspending agent was SA™-1015, available fromHalliburton Energy Services, Inc.

For Sample Fluid 45, the sample comprised a mixture of CKD (80% byweight), fly ash (16% by weight), and hydrate lime (4% by weight).Sufficient water was included in the sample to provide a density of 13.5ppg. The CKD used was from Holcim (US) Inc., Ada, Okla. The fly ash usedwas POZMIX® cement additive, from Halliburton Energy Services, Inc.

The static gel strength of the samples was measured in accordance withAPI Recommended Practice on Determining the Static Gel Strength ofCement Formations, ANSI/API Recommended Practice 10B-6. FIGS. 4 and 5show the static gel strength measurements for Sample Fluids 44 and 45,respectively, as a function of time. As seen in the figures, the samplesprogress through the transition time, defined as the time between 100SGS and 500 SGS, very quickly with a total transition time of 19 minutesfor the sample 34 and 6 minutes for sample 35. These short transitiontimes are faster than most cement compositions.

EXAMPLE 11

The following tests were performed to evaluate the static gel strengthdevelopment of consolidating spacer fluids. Two samples, labeled SamplesFluids 46 and 47 were prepared having a density of 13.002 and 10.999 ppgrespectively using various concentrations of additives. The componentconcentrations of each sample are as follows:

For Sample Fluid 46, the sample comprised a blend of CKD (100% byweight), POZMIX® (50% by weight of the CKD), He-601 (1% by weight of theCKD), HR®-25 (PB) (0.6% by weight of the CKD), and D-Air 5000 (0.5% byweight of the CKD). Sufficient water was included in the sample toprovide a density of 13.002 ppg. The CKD used was from Holcim (US) Inc.,Ada, Okla. POZMIX® cement additive is from Halliburton Energy Services,Inc. HR®-601 is a cement retarder available from Halliburton EnergyServices, Inc. HR®-25 is a cement retarder available from HalliburtonEnergy Services, Inc. D-Air™ 5000 is a defoamer available fromHalliburton Energy Services, Inc.

For Sample Fluid 47, the sample comprised a blend of CKD (100% byweight), SA-1015 (0.4% by weight of the CKD), and D-Air 5000 (0.5% byweight of the CKD). Sufficient water was included in the sample toprovide a density of 10.999 ppg. The CKD used was from Holcim (US) Inc.,Ada, Okla. SA™-1015 is a suspending agent available from HalliburtonEnergy Services, Inc. D-Air™ 5000 is a defoamer available fromHalliburton Energy Services, Inc.

The static gel strength of the samples was measured in accordance withAPI Recommended Practice on Determining the Static Gel Strength ofCement Formations, ANSUAPI Recommended Practice 10B-6. Table 8 shows thestatic gel strength measurements for samples 36 and 37, respectively.

TABLE 8 Difference between 100 lbf/ Time to reach Time to reach 100ft^(s) and Sample Temp 100 lbf/100 ft^(s) 500 lbf/100 ft^(s) 500 lbf/100ft^(s) Fluid (° F.) (hr:min) (hr:min) (hr:min) 46 220 3:25 5:04  1:39 47220 3:07 3:17 00:10As seen in the table, Sample Fluid 47 progresses through the transitiontime, defined as the time between 100 SGS and 500 SGS, very quickly witha total transition time of 10 minutes. Sample Fluid 46 is much slowertaking over an hour to progress through the transition time. The shorttransition time of Sample Fluid 47 is faster than most cementcompositions.

It should be understood that the compositions and methods are describedin terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Although individual embodiments arediscussed, the invention covers all combinations of all thoseembodiments. Furthermore, no limitations are intended to the details ofconstruction or design herein shown, other than as described in theclaims below. Also, the terms in the claims have their plain, ordinarymeaning unless otherwise explicitly and clearly defined by the patentee.It is therefore evident that the particular illustrative embodimentsdisclosed above may be altered or modified and all such variations areconsidered within the scope and spirit of the present invention. Ifthere is any conflict in the usages of a word or tenni in thisspecification and one or more patent(s) or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

What is claimed is:
 1. A method of evaluating a boundary between aconsolidating spacer fluid and a cement composition comprising:introducing a consolidating spacer fluid into a well bore to displace atleast a portion of a drilling fluid from the well bore; introducing acement composition into the well bore behind the consolidating spacerfluid; allowing at least a portion of the consolidating spacer fluid toconsolidate in the well bore; and determining the boundary between thecement composition and the consolidating spacer fluid based on presenceof a tagging material in the well bore, wherein the tagging materialcomprises a thermal neutron absorbing material.
 2. The method of claim1, wherein the determining the boundary comprises running a neutron login the well bore.
 3. The method of claim 1, wherein the tagging materialis present in a first portion of the cement composition that isintroduced into the well bore.
 4. The method of claim 3, wherein thetagging material is present in an amount in a range of from about 0.1%to about 5% by weight of the first portion.
 5. The method of claim 1,wherein the tagging material is present in a trailing portion of theconsolidating spacer fluid.
 6. The method of claim 5, wherein thetagging material is present in an amount in a range of from about 0.1%to about 5% by weight of the trailing portion.
 7. The method of claim 1,wherein the thermal neutron absorbing material comprises at least onetagging material selected from the group consisting of boron carbide,cadmium hydroxide, and any combination thereof.
 8. The method of claim1, further comprising running a bond log on the consolidated portion ofthe consolidating spacer fluid in the well bore to measure bonding ofthe consolidating spacer fluid to a pipe string in the well bore.
 9. Themethod of claim 1, wherein the consolidating spacer fluid comprisescement kiln dust.
 10. The method of claim 1, wherein the consolidatingspacer fluid comprises lime kiln dust.
 11. The method of claim 1,wherein the consolidating spacer fluid comprises a partially calcinedkiln feed comprising SiO2, Al2O3, Fe2O3, CaO, MgO, SO3, Na2O, and K2O.12. The method of claim 1, wherein the consolidating spacer fluidcomprises at least one additive selected from the group consisting of afree water control additive, a lightweight additive, a foaming agent, asupplementary cementitious material, a weighting agent of any suitablesize, a viscosifying agent, a fluid loss control agent, a lostcirculation material, a filtration control additive, a dispersant, adefoamer, a corrosion inhibitor, a scale inhibitor, a formationconditioning agent, a water-wetting surfactant, and any combinationthereof.
 13. The method of claim 1, wherein the consolidating spacerfluid comprises at least one additive selected from the group consistingof kiln dust, gypsum, fly ash, bentonite, hydroxyethyl cellulose, sodiumsilicate, a hollow microsphere, gilsonite, perlite, a gas, an organicpolymer, a biopolymer, latex, ground rubber, a surfactant, crystallinesilica, amorphous silica, silica flour, fumed silica, nano-clay, salt,fiber, hydratable clay, rice husk ash, micro-fine cement, metakaolin,zeolite, shale, pumicite, Portland cement, Portland cement intergroundwith pumice, barite, slag, lime, and any combination thereof.
 14. Themethod of claim 1, wherein the portion of the consolidating spacer fluidconsolidates in the well bore to have at least one property selectedfrom the group consisting of: (i) a yield point of from about 25 Pascalsto about 250 Pascals, (ii) a static gel strength of from about 70lbf/100 ft² to about 500 lbf/100 ft², (iii) a yield limit in compressionfrom about 1 psi to about 2,000 psi, and (iv) an unconfined uniaxialcompressive strength of from about 5 psi to about 10,000 psi.
 15. Themethod of claim 1, wherein the portion of the consolidating spacer fluidhas a zero gel time of about 8 hours or less.
 16. The method of claim 1,wherein the portion of the consolidating spacer fluid has a transitiontime of about 45 minutes or less.
 17. The method of claim 1, wherein theconsolidating spacer consolidates in the well bore to have a transitiontime that is shorter than a transition time of the cement composition.18. A method of evaluating a boundary between a consolidating spacerfluid and a cement composition comprising: introducing a consolidatingspacer fluid into a well bore to displace at least a portion of adrilling fluid from the well bore, wherein the consolidating spacerfluid comprises water and cement kiln dust; introducing a cementcomposition into the well bore behind the consolidating spacer fluid,wherein a first portion of the cement composition comprises a thermalneutron absorbing material; allowing at least a portion of theconsolidating spacer fluid to consolidate in the well bore; anddetermining the top of the cement composition in the well bore based onpresence of the thermal neutron absorbing material in the first portion.19. The method of claim 18, wherein the determining the top of thecement composition comprises running a neutron log in the well bore. 20.The method of claim 18, wherein the thermal neutron absorbing materialis present in an amount in a range of from about 0.1% to about 5% byweight of the first portion.
 21. The method of claim 18, wherein thethermal neutron absorbing material comprises at least one taggingmaterial selected from the group consisting of boron carbide, cadmiumhydroxide, and any combination thereof.
 22. The method of claim 18,further comprising running a bond log on the consolidated portion of theconsolidating spacer fluid in the well bore to measure bonding of theconsolidating spacer fluid to a pipe string in the well bore.
 23. Themethod of claim 18, wherein the consolidating spacer fluid comprises atleast one additive selected from the group consisting of a free watercontrol additive, a lightweight additive, a foaming agent, asupplementary cementitious material, a weighting agent of any suitablesize, a viscosifying agent, a fluid loss control agent, a lostcirculation material, a filtration control additive, a dispersant, adefoamer, a corrosion inhibitor, a scale inhibitor, a formationconditioning agent, a water-wetting surfactant, and any combinationthereof.
 24. The method of claim 18, wherein the consolidating spacerfluid comprises at least one additive selected from the group consistingof gypsum, fly ash, bentonite, hydroxyethyl cellulose, sodium silicate,a hollow microsphere, gilsonite, perlite, a gas, an organic polymer, abiopolymer, latex, ground rubber, a surfactant, crystalline silica,amorphous silica, silica flour, fumed silica, nano-clay, salt, fiber,hydratable clay, rice husk ash, micro-fine cement, metakaolin, zeolite,shale, pumicite, Portland cement, Portland cement interground withpumice, barite, slag, lime, and any combination thereof.
 25. The methodof claim 18, wherein the portion of the consolidating spacer fluidconsolidates in the well bore to have at least one property selectedfrom the group consisting of: (i) a yield point of from about 25 Pascalsto about 250 Pascals, (ii) a static gel strength of from about 70lbf/100 ft² to about 500 lbf/100 ft², (iii) a yield limit in compressionfrom about 1 psi to about 2,000 psi, and (iv) an unconfined uniaxialcompressive strength of from about 5 psi to about 10,000 psi.
 26. Themethod of claim 18, wherein the portion of the consolidating spacerfluid has a zero gel time of about 8 hours or less.
 27. The method ofclaim 18, wherein the portion of the consolidating spacer fluid has atransition time of about 45 minutes or less.
 28. The method of claim 18,wherein the first portion of the cement composition has a length in thewell bore of about 20 feet or less.
 29. The method of claim 18, whereinthe consolidating spacer consolidates in the well bore to have atransition time that is shorter than a transition time of the cementcomposition.
 30. A system for evaluating spacer fluid boundaries in awell bore, comprising: a consolidating spacer fluid; a cementcomposition; mixing equipment for separately mixing the consolidatingspacer fluid and the cement composition; and pumping equipment forseparately delivering the consolidating spacer fluid and the cementcomposition to a well bore, wherein at least one of the consolidatingspacer fluid or the cement composition comprises a tagging materialcomprising a thermal neutron absorbing material.
 31. The system of claim30, wherein the thermal neutron absorbing material comprises at leastone tagging material selected from the group consisting of boroncarbide, cadmium hydroxide, and a combination thereof.
 32. The system ofclaim 30, wherein the consolidating spacer fluid comprises a kiln dust.33. The system of claim 32, wherein the kiln dust comprises at least onekiln dust selected from the group consisting of a cement kiln dust, alime kiln dust, and a combination thereof.
 34. The system of claim 30,wherein the consolidating spacer fluid comprises a partially calcinedkiln feed comprising SiO2, Al2O3, Fe2O3, CaO, MgO, SO3, Na2O, and K2O.35. A method of evaluating a boundary between a consolidating spacerfluid and a cement composition comprising: introducing a consolidatingspacer fluid into a well bore to displace at least a portion of adrilling fluid from the well bore; introducing a cement composition intothe well bore behind the consolidating spacer fluid; allowing at least aportion of the consolidating spacer fluid to consolidate in the wellbore; determining the boundary between the cement composition and theconsolidating spacer fluid based on presence of a tagging material inthe well bore; and running a bond log on the consolidated portion of theconsolidating spacer fluid in the well bore to measure bonding of theconsolidating spacer fluid to a pipe string in the well bore.
 36. Themethod of claim 35, wherein the determining the boundary comprisesrunning a neutron log in the well bore.
 37. The method of claim 35,wherein the tagging material comprises at least one tagging materialselected from the group consisting of boron carbide, cadmium hydroxide,and any combination thereof.
 38. The method of claim 35, wherein theconsolidating spacer fluid comprises a kiln dust.
 39. The method ofclaim 38, wherein the kiln dust comprises at least one partiallycalcined kiln feed selected from the group consisting of a cement kilndust, a lime kiln dust, and a combination thereof.
 40. The method ofclaim 35, wherein the consolidating spacer fluid comprises a partiallycalcined kiln feed comprising SiO2, Al2O3, Fe2O3, CaO, MgO, SO3, Na2O,and K2O.
 41. A method of evaluating a boundary between a consolidatingspacer fluid and a cement composition comprising: introducing aconsolidating spacer fluid comprising a kiln dust into a well bore todisplace at least a portion of a drilling fluid from the well bore;introducing a cement composition into the well bore behind theconsolidating spacer fluid; allowing at least a portion of theconsolidating spacer fluid to consolidate in the well bore; anddetermining the boundary between the cement composition and theconsolidating spacer fluid based on presence of a tagging material inthe well bore.
 42. The method of claim 41, wherein the determining theboundary comprises running a neutron log in the well bore.
 43. Themethod of claim 41, wherein the tagging material comprises a thermalneutron absorbing material.
 44. The method of claim 41, wherein thetagging material comprises at least one tagging material selected fromthe group consisting of boron carbide, cadmium hydroxide, and anycombination thereof.
 45. The method of claim 41, wherein the kiln dustcomprises cement kiln dust.
 46. The method of claim 41, wherein the kilndust comprises lime kiln dust.
 47. The method of claim 41, wherein thekiln dust comprises a partially calcined kiln feed comprising SiO2,Al2O3, Fe2O3, CaO, MgO, SO3, Na2O, and K2O.